Integrated Vacuum Distillate Recovery Process

ABSTRACT

A system for recovering diesel products from a feed stream comprises an atmospheric crude unit, a vacuum crude unit, and a vacuum distillate recovery unit. The atmospheric crude unit comprises a crude feed inlet line, a diesel product outlet line, an atmospheric gas oil product outlet line, and a residual product outlet line. The vacuum crude unit comprises a residual product inlet line in fluid communication with the residual product outlet line from the atmospheric crude unit, a light vacuum gas oil product outlet line, and an overhead vapor outlet line. The vacuum distillate recovery unit comprises a gas oil inlet line, an overhead product line, and a second diesel product outlet line. The gas oil inlet line is in fluid communication with the atmospheric gas oil product outlet line from the atmospheric crude unit and the light vacuum gas oil product outlet line from the vacuum crude unit.

CROSS-REFERENCE TO RELATED APPLICATIONS

Not Applicable.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not applicable.

REFERENCE TO A MICROFICHE APPENDIX

Not applicable.

BACKGROUND

Diesel engines are widely used in a number of applications. Environmental concerns have led to many nations setting strict regulations that set minimum cetane number, sulfur content, aromatics content, as well as other diesel fuel specifications. These along with a shift in gasoline and diesel consumption require reassessing refinery configurations. The demand for diesel has been increasing worldwide. Countries outside of the U.S. are heavily reliant on diesel fuel. Strong international demand for diesel in rapidly developing countries like China and India has placed a premium on diesel imports. While the U.S. is a gasoline dominant motor fuels market, the demand for gasoline peaked in 2007 and has been decreasing since. Demand for diesel has been increasing. Comparing October 2010 demand to that of October 2012, demand for on-road diesel fuel increased 11.8% while gasoline demand decreased by 3.4%. The U.S. Energy Information Administration's Annual Energy Outlook 2014 publication provides the projections of Motor gasoline and diesel fuel consumption through the year 2040. Figure MT-57 of this publication shows these fuels trending in opposite directions with motor gasoline consumption falling by 2.1 MMbpd from 2012 to 2040, while diesel fuel consumption increases by 0.9 MMbpd. The bulk of the predicted changes in consumption occur prior to 2030. Too meet the growing demand for diesel it is expected that new refinery projects will involve shifting production from gasoline to diesel fuels.

SUMMARY

In an embodiment, a system for recovering diesel products from a feed stream comprises an atmospheric crude unit, a vacuum crude unit, and a vacuum distillate recovery unit. The atmospheric crude unit comprises a crude feed inlet line, a diesel product outlet line, an atmospheric gas oil product outlet line, and a residual product outlet line. The vacuum crude unit comprises a residual product inlet line, a light vacuum gas oil product outlet line, and an overhead vapor outlet line. The residual product inlet line is in fluid communication with the residual product outlet line. The vacuum distillate recovery unit comprises a gas oil inlet line, an overhead product line, and a second diesel product outlet line. The gas oil inlet line is in fluid communication with the atmospheric gas oil product outlet line from the atmospheric crude unit and the light vacuum gas oil product outlet line from the vacuum crude unit.

In an embodiment, a method of recovering diesel from a crude oil feed stream comprises separating a crude oil feed stream into a plurality of streams in an atmospheric crude unit, receiving the atmospheric gas oil stream and a light vacuum gas oil stream at a distillation column, and separating the atmospheric gas oil stream and the light vacuum gas oil stream into a plurality of product streams in the distillation column. The plurality of streams comprise a first diesel product stream, an atmospheric gas oil stream, and a residual product stream. The plurality of product streams comprise an overhead vapor stream, a second diesel product stream, and a medium gas oil stream.

In an embodiment, a method of recovering diesel comprises separating a crude oil feed stream into a plurality of product streams in an atmospheric crude unit, separating the residual product stream into a plurality of second product streams in a vacuum crude unit, receiving the atmospheric gas oil stream and the light vacuum gas oil stream at a distillation column, and separating the atmospheric gas oil stream and the light vacuum gas oil stream into a plurality of third product streams in the distillation column. The plurality of product streams comprises a first diesel product stream, an atmospheric gas oil stream, and a residual product stream. The plurality of second product streams comprises a light vacuum gas oil and an overhead stream, and the plurality of third product streams comprises a second diesel product stream.

These and other features will be more clearly understood from the following detailed description taken in conjunction with the accompanying drawings and claims.

BRIEF DESCRIPTION OF THE DRAWINGS

For a more complete understanding of the present disclosure and the advantages thereof, reference is now made to the following brief description, taken in connection with the accompanying drawings and detailed description:

FIG. 1 illustrates a simplified process flow diagram of an embodiment of an atmospheric crude unit and a vacuum crude unit. In this configuration diesel is only produced from the atmospheric crude column.

FIG. 2 illustrates another simplified process flow diagram of an embodiment of an atmospheric crude unit and a vacuum crude unit, where the vacuum column is configured for diesel recovery.

FIG. 3 illustrates still another simplified process flow diagram of an embodiment of an atmospheric crude unit and a vacuum crude unit with the addition of a vacuum preflash column configured for diesel recovery.

FIG. 4 illustrates a simplified block flow diagram of an embodiment of a vacuum distillate recovery process integrated with an atmospheric crude unit and a vacuum crude unit.

FIG. 5 illustrates a simplified process flow diagram of an embodiment of the vacuum distillate recovery process integrated with a vacuum crude unit.

FIG. 6 illustrates another simplified process flow diagram of an embodiment of the vacuum distillate recovery process integrated with a vacuum crude unit.

FIG. 7 illustrates still another simplified process flow diagram of an embodiment of the vacuum distillate recovery process integrated with a vacuum crude unit.

DETAILED DESCRIPTION OF THE EMBODIMENTS

In the drawings and description that follow, like parts are typically marked throughout the specification and drawings with the same reference numerals, respectively. The drawing figures are not necessarily to scale. Certain features may be shown exaggerated in scale or in somewhat schematic form and some details of conventional elements may not be shown in the interest of clarity and conciseness. Specific embodiments are described in detail and are shown in the drawings, with the understanding that the present disclosure is to be considered an exemplification of the principles of the invention, and is not intended to limit the invention to that illustrated and described herein. It is to be fully recognized that the different teachings of the embodiments discussed infra may be employed separately or in any suitable combination to produce desired results.

Unless otherwise specified, any use of any form of the terms “connect,” “engage,” “couple,” “attach,” or any other term describing an interaction between elements is not meant to limit the interaction to direct interaction between the elements and may also include indirect interaction between the elements described. In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . ”. The various characteristics mentioned above, as well as other features and characteristics described in more detail below, will be readily apparent to those skilled in the art with the aid of this disclosure upon reading the following detailed description of the embodiments, and by referring to the accompanying drawings.

The term “True Boiling Point” (TBP) refers to the test method for determining the boiling point of hydrocarbons which corresponds to ASTM D2892 for the production of a liquefied gas, distillate fractions, and residuum of standardized quality on which analytical data can be obtained, and the determination of yields of the above fractions by both mass and volume from which a graph of temperature versus mass % distilled is produced using fifteen theoretical plates in a column with a 5:1 reflux ratio.

The term “diesel” or “diesel fuel” refers to hydrocarbons having boiling points in the range of from about 270° F. to about 750° F. using the True Boiling Point method.

The term “virgin diesel” refers to diesel or diesel fuel removed from the crude feed, where the diesel is not the product of a chemical transformation of another hydrocarbon component.

The terms “gas oils”, Atmospheric Gas Oil (“AGO”), Light Vacuum Gas Oil (“LVGO”), Heavy Vacuum Gas Oil (“HVGO”), Light Gas Oil (“LGO”), and Medium Gas Oil (“MGO”) refer to hydrocarbon streams having boiling points that can range anywhere from about 270° F. to about 1150° F. using the True Boiling Point method. However, the gas oil hydrocarbons, with diesel components removed, have boiling points in the range of about 750° F. to about 1150° F. using the True Boiling Point method.

The term “column” means a distillation column for separating one or more components of different volatilities.

The systems and methods described herein enable refineries with vacuum crude units an economical means to improve the production of virgin diesel. In the present system, a single distillate recovery column can be integrated with the low pressure operation of a vacuum crude unit, eliminating the need for an additional overhead vacuum system. A pump-around heat removal section provides for condensing of the diesel product and the diesel/gas oil fractionating zone hydrocarbon reflux stream. The high reflux to distillate ratio of the fractionating bed below the vacuum column diesel draw provides for good separation between the diesel and gas oil hydrocarbons enabling good diesel yields. The feed stock fed to the separation unit is comprised of refinery streams with hydrocarbon components that boil in the diesel through gas oil range (i.e. AGO, LVGO, etc.). The prior removal of lighter and heavier boiling range components from these feedstock streams provide significant benefits to the ability to fractionate diesel out of the feedstock. Charging of the feeds to the vacuum distillate recovery column at a relatively high temperature from the other units combined with low pressure operation normally eliminates the need for feed preheat or a reboiler system. Feed preheat and/or reboiler systems with a stripping section below the feed is optional to provide for flexibility of feed enthalpy and improve diesel recovery.

The present system and methods enable refineries with atmospheric and vacuum crude units to increase diesel recovery from crude by integrating these process units with the vacuum distillate recovery unit described herein. The novel processing schemes described herein are advantageous in that they do not negatively affect the reliability and operability of the atmospheric and vacuum crude units, they provide a method to convert vacuum units to one that can achieve maximum recovery of virgin diesel, they are simple in design, and they are economical.

A design of the atmospheric crude unit 2 and a vacuum crude unit 6 are shown in the system 150 of FIG. 1. The atmospheric crude unit and the vacuum crude unit are generally designed to separate a crude oil feed stream into a number of product streams. The separation process generally begins by desalting the crude oil to remove salts which can be harmful to downstream equipment. The salts are generally removed from the crude oil stream by mixing the crude oil with water and heating the mixture to a temperature between about 200° F. and about 300° F. Various types of heaters, heat exchangers, and/or heat integration schemes (e.g., heat exchangers using hot process streams) can be used to raise the crude oil to this temperature range. The salt may then be absorbed into the aqueous phase. The mixture can then be passed to a desalter, where the water containing the salts is separated from the crude oil. The crude oil having the majority, if not all, of the salt removed can then be further heated to a temperature between about 650° F. and about 750° F. using a heater (e.g., a furnace), heat exchanger, and/or heat integration schemes.

The heated crude can then pass to the atmospheric crude column 101 in the atmospheric crude unit 2 to produce a plurality of outlet product streams. The atmospheric crude unit 2 generally comprises a distillation column where the crude can partially vaporize and separate within the column. The vapor can pass upwards through the column and contact a liquid descending within the column to separate the various components within the crude oil feed into different boiling range fractions. The higher molecular weight or higher boiling components may pass to the lower portion of the column where a portion of the liquid may be vaporized. Steam may be used to provide the heat to vaporize a portion of the crude within the column. At various stages along the length of the column, liquid can be extracted from trays and sent to side draws or side strippers to produce an outlet product stream. Various additional devices or units can also be used with the atmospheric crude unit 2 such as pump-arounds, heat exchangers, and the like. The overhead stream can be at least partially compressed and/or condensed and a portion of the liquid returned to the column as reflux. The resulting overhead product from the atmospheric crude unit 2 comprises light ends/naphtha. Separate side stream draws can result in a product stream comprising several fractions such as a kerosene fraction, a diesel fraction, and an atmospheric gas oil fraction.

The bottoms product from the atmospheric crude unit 2 includes the residual heavy components, generally referred to as residue. The residue may be further separated in the vacuum crude unit 6. The residue can be sent directly to the vacuum crude unit 6 and/or cooled and stored in a storage unit such as one or more storage tanks. In some embodiments, additional streams from other atmospheric crude units can be transferred to the vacuum crude unit 6, directly and/or from a storage location. The stream passing to the vacuum crude unit can be reheated as needed prior to being sent to the vacuum crude unit 6.

In order to separate the residue, the bottoms stream from the atmospheric crude unit 2 can be heated in a furnace 52 and passed to the column 56. The upper limit of the temperature of the residue in the furnace 52 is set by the temperature at which excessive cracking of the oil occurs. In general, the residue stream is heated to a temperature below the excessive cracking temperature to avoid fouling and high tube metal temperatures. The column 56 is in fluid communication with a vacuum system through an overhead line 62, which sets the pressure at the top of the column 56. The pressure changes in each section along the column 56 determine the pressure at the bottom of the column 56. In general, a vacuum crude unit 6 does not use side strippers, but a plurality of streams can be taken off the column along its length.

The heated residue is passed to the vacuum crude column 56 in the vacuum crude unit 6 where a portion of the residue vaporizes. As the vapors rise, one or more condensation sections can be used to condense various fractions that can be withdrawn from the column. At least a portion of the withdrawn liquid can be cooled and returned to the column as liquid. The resulting separation of the residue within the vacuum crude column 56 can result in a number of outlet streams. The overhead stream can include the lighter components in the residue, coil steam, stripping steam, light hydrocarbons generated from cracking of the oil in the heater, and/or air from leakage. An upper side stream comprising the light vacuum gas oils and a lower side stream comprising the heavy vacuum gas oils can be taken out of the column 56. The bottoms stream includes the vacuum tower bottoms, which are generally heavier components that can be sent to a coker or visbreaker unit to produce higher value products. The vacuum crude unit 6 may have other product streams such as Medium Vacuum Gas Oil (MVGO), a slop wax product, and/or one or more additional streams. In some embodiments, one or more of the streams passing out of the vacuum crude column 56 illustrated in FIG. 1 may not be present.

Since the U.S. has had a gasoline dominate motor fuels market, most U.S. refineries are built to maximize gasoline production with diesel being a secondary product. As shown in the system 150 illustrated in FIG. 1, the design of the atmospheric crude unit and vacuum crude unit are of a design such that the only diesel product is from the atmospheric crude unit 2. The Atmospheric Gas Oil (AGO) and the Light Vacuum Gas Oil (LVGO) streams from these units normally retain a significant quantity of diesel boiling range components. In some cases, the combined diesel boiling range components in these streams can include approximately 6,000 to 8,000 barrels per day (bpd) on a 150,000 bpd (i.e., 150 Mbpd) crude unit. Based on the reasoning that these refineries were originally designed to maximize gasoline production, this configuration was logical at that time. The gas oil streams can be further processed in a Fluid Catalytic Cracking Unit (FCCU) to convert the majority of these streams to gasoline range components. It should be further noted that the diesel range hydrocarbons produced from the downstream FCCU and coker unit is of a poor quality. In particular, the cetane value of these streams is insufficient for diesel sales. These units also increase the aromatic content and produce olefins, which has become more of an environmental concern and normally requires further processing to reduce or eliminate these components. This processing unit configuration is inefficient in meeting the current refining industry needs of shifting yields from gasoline to high quality diesel.

FIG. 2 illustrates another crude separation unit design such as those in many European refineries as well as refineries in other overseas countries. This crude separation unit configuration is built according to process flow schemes developed to improve the diesel production. The typical design of the Atmospheric and Vacuum Crude Units in these refineries are of such a design that diesel is produced from the atmospheric crude unit 2 as well as the vacuum crude unit 6. The high reflux to distillate ratio of the fractionating bed below the vacuum crude column 56 diesel draw provides for good separation between the diesel and gas oil hydrocarbons enabling good diesel yields.

Some vacuum units in the U.S. have incorporated similar vacuum crude unit designs to those found overseas. However, the vacuum crude unit designs of the U.S., which were not designed to produce diesel, normally are mechanically limited from conversion to enable diesel production. It is also not economical to replace a vacuum column with a design similar to those in Europe. The extended down time and expensive capital costs cannot be justified by the increase in diesel yield alone.

There are two other design practices that can be used to increase virgin diesel production. The first is addition of a vacuum preflash column, and the second incorporates modifications associated with the atmospheric crude column to enable increased diesel production. While virgin diesel yields can be increased by both of these design practices there are underlying issues which make both poor design choices for most refineries, several of which are discussed below.

FIG. 3 illustrates a crude separation system having a vacuum preflash column 93. The use of the vacuum preflash column 93 can be used to increase the virgin diesel recovery from the system. However, increasing the cut point prior to the vacuum crude column 56 (e.g., removing lighter boiling range components from the vacuum column feed) has a negative effect on the process unit's reliability and heavy vacuum gas oil (HVGO) cut point. Vacuum crude unit 6 feed stocks have a thermal limit before excessive oil cracking occurs, leading to the formation of coke and components that lead to fouling and/or plugging of the process equipment. Oil cracking is a function of oil temperature and residence time. Increasing the HVGO cut point in the vacuum crude unit is determined by the column flash zone temperature and pressure. Pressure is set by the column vacuum system (e.g., the overhead ejector system pressure) and the column pressure drop. The temperature is set by the heater firing, which is limited by thermal stability of the vacuum crude unit feed. For a given flash zone temperature and pressure, a heavier feed changes the flash zone vapor and liquid equilibrium such that less oil is vaporized. Thus, adding a vacuum preflash column 93 yields a heavier feed to the vacuum column 56 resulting in lowering the maximum obtainable HVGO cut point. At the lower cut point, the yield of lower value VTB product is increased at the expense of the higher value HVGO product. In addition, the heavier feed to the vacuum column feed heater 52 decreases the vaporization of the feed in the heater 52, which increases the heater oil residence time. Heater reliability as well as downstream equipment reliability is reduced due to the formation of coke and consequential equipment fouling. Vacuum heater 52 fouling is a primary cause of short vacuum crude unit 6 run times. Refinery operating experience has shown that coking in the bottom of a vacuum preflash column 93 can also be a problem. The column itself increases the oil residence time and at the high operating temperatures can lead to oil instability and coke formation. Oil cracking can produce light ends, which increases the load on the vacuum column ejector system. This increases the column pressure and further reduces the HVGO cut point. In addition, as a result of the high temperature and large volume of feed, a vacuum preflash column 93 and its associated peripheral equipment is expensive compared to the system described herein. Very few crude separation systems have been modified to this design configuration due to these problematic issues.

Modifications to existing atmospheric crude columns and their peripheral equipment can be made to increase virgin diesel yield. Some of the modifications include increasing the atmospheric column feed enthalpy by increasing feed heater firing and/or feed preheat train modifications, increasing the atmospheric tower bottoms (ATB) stripping steam rate, increasing the AGO stripper steam rate, and/or increasing the theoretical fractionating stages in the Diesel/AGO, Wash Zone, and stripping sections. The addition of extra theoretical fractionating stages is often limited due to limited amount of available space in an existing facility. These changes typically require modifications to the upper atmospheric crude column 101 internals up through the condensing zones to accommodate the additional vapor and liquid loadings and additional heat removal requirements as well as modifications to the associated pumparound circuit/crude preheat train. Even with all of these modifications, a significant amount of diesel range material cannot normally be recovered. It should be noted that compared to the system described herein, the fractionating zone for separation of the diesel from the gas oils in the atmospheric crude column 101 has inherently lower liquid to vapor (LN) ratios due to the large quantity of light ends, naptha, kerosene, and steam in the vapor phase, making the recovery of diesel much easier in the present system processing scheme. Also, increasing the ATB cut point, which may result in a heavier vacuum column feed composition, can lead to the same problems noted with the vacuum preflash column 93 above including a reduction in the vacuum crude unit 6 reliability and a decreased HVGO cut point (e.g., resulting in downgrading the gas oils to the lower value VTB product). More importantly, these changes increase the atmospheric crude column 101 vapor and liquid loadings and consume atmospheric crude column capacity. This processing capacity could alternatively be used to expand refinery throughput. The atmospheric crude column 101 capacity is a high capital cost limitation for expansion of a refineries capacity. As a result of these shortcomings, this approach to increasing diesel recovery is usually not recommended especially when considering the long term objectives of the refinery.

Research has been conducted in the last 35 years to increase total refinery diesel yield. The primary focus has been on the use of hydrocracker conversion units. Additional information on hydrocracker conversion units can be found in U.S. Pat. Nos. 8,840,854, 7,892,418, 6,676,828, 6,210,563, and 6,204,426, each of which is incorporated herein by reference in its entirety. These references provide information regarding conversion units used to increase diesel production. These high pressure and temperature units are beneficial in maximizing total refinery diesel yields. However, they are expensive to build and operate. As a result, it would be beneficial to remove all of the quality virgin diesel from the crude oil feed and utilize the conversion units to convert low value gas oils to higher value products.

FIG. 4 show simplified process flow diagrams of an embodiment of a system 8 of using a vacuum distillate recovery unit 4. The atmospheric crude unit 2 and the vacuum crude unit 6 can include units as described above, and the vacuum distillate recovery unit 4 can be integrated with these units. Variations in the atmospheric crude unit 2 and the vacuum crude unit 6 are generally described in more detail herein. Further, additional equipment associated with the various units such as pumps, control valves, and other basic equipment as well as the distillation column internals design necessary for the operation of the unit are not shown in the drawings, but would be understood by one of ordinary skill in the art with the aid of this disclosure.

The system 8 comprises an atmospheric crude unit section 2, a vacuum crude unit section 6, and a vacuum distillate recovery column section 4. The system 8 also includes a vacuum system 64 in fluid communication with the vacuum crude unit 6 and the vacuum distillate recovery unit 4. The vacuum system 64 is normally considered a part of the vacuum crude unit 6 but is illustrated as a separate unit in FIGS. 4-7 for clarity and purposes of discussion. The operating pressure of the vacuum unit, and therefore the vacuum crude unit 6 and the vacuum distillate recovery unit 4, varies due to the design and operation of each unit. In an embodiment, the vacuum system 64 may provide a low pressure source having a pressure between about 2 mmHg to about 100 mmHg absolute. The vacuum system 64 can include any suitable type of vacuum devices such as a multi-stage vacuum ejector system and possibly a liquid ring pump, or the like. In an embodiment, a low pressure vacuum crude unit 6 operating in wet mode can use a three-stage ejector system and may also have a liquid ring pump on the backend to further compress the non-condensable components. To obtain very low operating pressures, the ejectors can consume a significant amount of steam and the exchangers can use a significant quantity of cooling water. Steam generation and cooling water towers can be used to supply the utility streams. The cost of the ejector system and the offsite utilities is generally high.

As described in more detail herein, the vacuum distillate recovery unit 4 serves to separate a gas oil fraction into one or more outlet fractions including a diesel fraction. As shown in FIG. 4, the vacuum distillate recovery unit 4 may be coupled to the vacuum system 64 in order to operate at a low pressure. In an embodiment, the vacuum distillate recovery unit 4 is in fluid communication with the vacuum system 64 through an overhead line 20. The overhead line 20 is shown to split into lines 22 and 24, one or both of which may be used in any particular implementation. Line 22 is in direct fluid communication with the vacuum system 64, and line 24 is in fluid communication with an upper portion of a vacuum column in the vacuum crude unit 6. The use of line 22 and/or line 24 allows for low pressure operation of the vacuum distillate recovery process 4 by sharing the resources of the vacuum system 64. In an embodiment, overheard line 20 can be in fluid communication with the vacuum crude unit 6 through line 24 instead of line 22. A pressure control valve may be present in line 20 that may be used to control the pressure within the vacuum distillate recovery process.

In an embodiment, the feed to the vacuum distillate recovery unit 4 includes the AGO fraction from the atmospheric crude unit 2 as well as a LVGO fraction from the vacuum crude unit. In some embodiments, a pump may not be present between the vacuum crude unit 6 and the vacuum distillate recovery unit 4 in line 12 or line 16. In order to provide the LVGO fraction to the vacuum distillate recovery unit 4, the pressure within the vacuum distillate recovery unit 4 at the line 16 inlet location may be lower than the pressure of line 12 at the point it joins line 16 and/or enters the distillation column within the vacuum distillate recovery unit 4.

The LVGO stream in line 12 from the vacuum crude unit 6 can be combined with the AGO stream in line 10 from the atmospheric crude unit 2 and/or another component stream in line 14 prior to introducing the mixture into the vacuum distillate recovery unit 4. The temperature of the AGO stream may be greater than the temperature of the LVGO stream, and the combination of the streams may provide an inlet stream in line 16 to the vacuum distillate recovery unit 4 that does not require feed preheat. In some embodiments, the LVGO stream in line 12 and/or another component stream in line 14 may be introduced into the vacuum distillate recovery unit 4 separately from the AGO stream in line 10.

In an embodiment, a feed preheater may be used to preheat the LVGO stream in line 12, the AGO stream in line 10, the optional stream in line 14, and/or the combined inlet stream in line 16. The AGO stream in line 10 may generally have a sufficient enthalpy that it does not need preheating unless it is cooled prior to being fed to vacuum distillate recovery unit 4. The feed preheat of these lines can be provided by a feed pre-heater. In some embodiments, heat exchange with another stream may be used to pre-heat any of these streams. For example, the MGO stream in line 38 may be heat exchanged with the LVGO stream in line 12, the optional stream in line 14, the AGO stream in line 10, and/or the combined inlet stream in line 16.

In operation, a method of operating the system 8 may begin with the crude feed in line 100. The crude feed is first fed to the atmospheric crude unit 2 in line 100. As described above, various treatment processes such as desalting and heating using heat integration and/or furnaces can be carried out before the crude feed reaches the atmospheric crude unit 2 and/or as a part of the processing within the atmospheric crude unit 2. Within the atmospheric crude unit 2, the crude feed can be separated into a plurality of product streams, which can comprise a light ends/naphtha fraction through line 102, a stream comprising a kerosene fraction in line 103, a stream comprising a diesel fraction in line 104, a stream comprising an AGO fraction in line 10, and a stream comprising an atmospheric tower bottoms product fraction (e.g., a residue fraction) in line 50. In some embodiments, all of the product streams from the atmospheric crude unit 2 may not be present, and/or other product and feed streams not shown may be used depending on the design of the atmospheric crude unit 2. In an embodiment, the atmospheric crude unit 2 may comprise side stripper columns from which the outlet lines 10, 104, and 103 may be drawn.

The Atmospheric Tower Bottoms (ATB) Product fraction (e.g., a residue fraction) in line 50 can pass to the vacuum crude unit 6 for further recovery of one or more gas oil fractions. In some embodiments, all or a portion of the ATB stream as well as potential ATB streams from other atmospheric crude units can be stored and sent from the storage to the vacuum crude unit 6 at a later time. A furnace may be used with the atmospheric tower bottoms product fraction in line 50 to pre-heat the feed to the vacuum crude unit 6. The vacuum system 64 may be in fluid communication with the upper portion of the vacuum crude unit 6 through line 62, which may determine the operating pressure profile within the vacuum crude unit 6. In an embodiment, the vacuum crude unit 6 may operate at a less than atmospheric pressure. Within the vacuum crude unit 6, the atmospheric tower bottoms product fraction (e.g., a residue fraction) in line 50 can be separated into a plurality of product streams, which can comprise a stream comprising an off-gas product in line 62, a stream comprising a LVGO fraction in line 12, a stream comprising a HVGO fraction in line 60, and a stream comprising a vacuum tower bottoms (VTB) product in line 58. As noted above, one or more of the streams illustrated in FIG. 4 may not be present and/or one or more additional streams such as a MVGO stream or a slop wax product stream may pass out of the vacuum crude unit 6. The off-gas product stream may pass to the vacuum system 64 through line 62. The stream comprising the LVGO fraction in line 12 may pass to the entrance of the vacuum distillate recovery unit 4 as described above.

The stream comprising the AGO fraction from the atmospheric crude unit 2, the stream comprising the LVGO fraction in line 12, and optionally, an additional component stream in line 14 may be introduced into the vacuum distillate recovery unit 4 in one or more lines (e.g., in line 16). In an embodiment, the additional component stream in line 14 may originate with one or more other separation units. For example, the additional components may originate from another crude unit, purchased gas oils, and/or other refinery units. The vacuum distillate recovery unit 4 may be in fluid communication with the vacuum system 64 as described above so that the vacuum distillate recovery unit 4 may operate at a less than atmospheric pressure. In some embodiments, the inlet location of the feed in line 16 may be at a lower pressure than the LVGO in line 12 from the vacuum crude unit 6.

The stream fed to the vacuum distillate recovery unit 4 may be separated to produce one or more product streams, which may comprise an overhead vapor stream in line 20, a stream comprising a diesel product fraction in line 32, optionally a stream comprising a Light Gas Oil (LGO) fraction in line 46, and a stream comprising a Medium Gas Oil (MGO) fraction in line 38. In an embodiment, fewer product streams may be present, and in some embodiments, additional product streams can be produced from the vacuum distillate recovery unit 4. Since the feeds to the atmospheric crude unit 2 and the vacuum distillate recovery unit 4 are different, the resulting diesel fractions produced in each column may also be different. While each diesel fraction may fall within the specifications for diesel fuel, the diesel fraction in line 32 may have a higher average molecular weight than the diesel fraction in line 104. The two diesel fraction streams 104, 32 can be used separately or combined in any amount, as described in more detail herein. In some embodiments, the diesel fraction in stream 32 comprises diesel range components but can also comprise other lighter distillate components such as jet fuel and kerosene fractions. A refinery configuration can include a distillate hydrotreater with a distillation column downstream of the vacuum distillate recovery unit 4 that can receive the diesel fraction in stream 32 and recover hydrotreated diesel as well as other products (e.g., naphtha, jet fuel, etc.).

Another embodiment of a crude separation system 48 is illustrated in FIG. 5. The system 48 comprises an atmospheric crude unit 2, a vacuum crude unit 6, and vacuum distillate recovery column 4. The atmospheric crude unit 2 may be the same or the similar to the atmospheric crude unit 2 described above. As described above, the atmospheric crude unit 2 can comprise associated equipment such as a desalter, a feed preheat train using one or more exchangers, one or more feed heaters, and a distillation column for separating the crude feed. The distillation column 101 may comprise various associated equipment such as side stripper columns, pump-around heat removal circuits, and/or overhead condensing and compression system. The atmospheric crude unit 2 distillation column 101 may generally operate at a pressure between about 5 psig and about 45 psig, where the pressure varies within the distillation column 101. In general, the pressure may be the lowest at the top of the column 101 and the highest at the bottom. The pressure differential may drive a vapor phase stream upwards in the column while a descending liquid may contact the vapor to effect a product separation. The temperature profile within the column 101 may depend on the pressure profile and the composition of the vapor and/or liquid along the length of the column 101. In some embodiments, the temperature within the column 101 may be between about 230° F. and about 740° F. Various internal separation devices such as trays, structured packing, side draws, and the like can be used within the distillation column 101.

The distillation column 101 may produce a plurality of product streams representing different fractions of the crude feed. The product streams may have overlapping boiling point ranges to some extent, though the boiling point ranges will generally include higher temperatures as the outlet location descends down the column 101. In an embodiment, the crude feed can be separated into a plurality of product streams within the atmospheric crude unit 2 distillation column 101 including a light ends/naphtha fraction in line 102, a stream comprising a kerosene fraction in line 103, a stream comprising a diesel fraction in line 104, a stream comprising an AGO fraction in line 10, and a stream comprising an atmospheric tower bottoms product fraction (e.g., a residue fraction) in line 50. The stream comprising the AGO fraction in line 10 will normally be stripped in a side stripper column. The stream comprising the AGO fraction in line 10 may comprise a number of components having boiling points in the diesel range. The conditions of the stream comprising the AGO fraction may vary based on the design and operation of the atmospheric crude unit 2 distillation column 101. In an embodiment, the stream comprising the AGO fraction may be at a pressure between about 10 psig and about 45 psig, or much higher if a pump is used, and have a temperature between about 600° F. and about 725° F. unless the stream is cooled. This temperature allows for a high feed enthalpy of the combined feed to the vacuum distillate recovery unit 4, which may beneficially provide feed vaporization in the flash zone of the distillation column 18 of the vacuum distillate recovery unit 4.

The atmospheric tower bottoms product fraction in line 50 may pass to a heater 52 where the stream in line 50 may be heated to a temperature in the range of from about 730° F. to about 795° F. As noted above, all or a portion of the ATB stream as well as potential ATB streams from other atmospheric crude units can be stored and sent from the storage to the vacuum crude unit 6 at a later time. In this embodiment, the streams can pass to a heater to be heated. Various types of heaters can be used to heat the stream in line 50, and any suitable heater may be used. In an embodiment, the heater 52 may comprise a furnace. The heated stream may pass out of the heater 52 and into the vacuum crude column 56.

The vacuum crude unit 6 may be the same or the similar to the vacuum crude unit 6 described above. As described above, the vacuum crude unit 6 can comprise associated equipment such as a feed heater and a vacuum crude unit distillation column. The distillation column 56 may comprise various associated equipment such as one or more pump-around heat removal circuits. The vacuum crude unit 6 distillation column 56 may generally operate at a pressure less than atmospheric. For example, the vacuum crude unit 6 distillation column 56 may operate at a pressure between about 2 mmHg and about 100 mmHg absolute, where the pressure varies within the distillation column 56. The pressure may be reduced to below atmospheric using the vacuum system 64 which is coupled to the upper portion of the distillation column 56 through line 62. In general, the pressure may be the lowest at the top of the column 56 and the highest at the bottom. The temperature profile within the column 56 may depend on the pressure profile and the composition of the vapor and/or liquid along the length of the column 56. In some embodiments, the temperature within the column 56 may be between about 110° F. and about 790° F. Various internal separation device such as trays, structured packing, side draws, and the like can be used within the distillation column 56.

The vacuum crude unit 6 distillation column 56 may produce a plurality of product streams representing different fractions of the atmospheric tower bottoms product fraction. The product streams may have overlapping boiling point ranges to some extent, though the boiling point ranges will generally include higher temperatures as the outlet location descends down the column. In an embodiment, the atmospheric tower bottoms product fraction fed to the distillation column 56 can be separated into a plurality of product streams within the vacuum crude unit 6 distillation column 56 including an off-gas product in line 62, a stream comprising a LVGO fraction in line 12, a stream comprising a HVGO fraction in line 60, and a stream comprising a vacuum tower bottoms (VTB) product in line 58. As noted above, one or more of the streams illustrated in FIG. 4 may not be present and/or one or more additional streams such as a MVGO stream or a slop wax product stream may pass out of the vacuum crude unit 6.

The stream comprising the LVGO fraction in line 12 may comprise a number of components having boiling points in the diesel range. As a result, the LVGO fraction stream may be passed to the vacuum distillate recovery unit 4 for further separation. The stream comprising the LVGO fraction may be at a pressure between about 5 mmHg and about 105 mmHg absolute at the point of draw-off and increase to near atmospheric pressure due to the static head of liquid in the outlet piping prior to a pump, if one is present. The temperature of the stream comprising the LVGO in line 12 may vary due to the design of the vacuum crude unit distillation column 56, though the temperature will generally be in the range of from about 220° F. to about 350° F. The stream comprising the VTB fraction in line 58 and/or the stream comprising the HVGO fraction in line 60 may leave the system 48 for further processing such as being sent to a coker unit or an FCC unit respectively.

As shown in FIG. 5, the vacuum distillate recovery unit 4 can comprise a distillation column 18. The distillation column 18 may comprise various associated equipment such as side stripper columns, pumparound heat removal circuits, side reboilers, reboiler, feed preheat, bottoms/feed exchanger, feed surge/flash drum, and/or overhead vacuum system. Various internal separation device such as trays, structured packing, side draws, and the like can be used within the distillation column 18. A reboiler system may or may not be present depending on the feed enthalpy, the column operating pressure, and the reflux ratio necessary to obtain the selected recovery of diesel.

The distillation tower 18 can be coupled to the vacuum system 64 through the overhead line 20, which can be coupled to line 24 and/or line 22 as described above. As a result of being in fluid communication with the vacuum system 64, the pressure within the distillation column 18 may be less than atmospheric. In an embodiment, the vacuum distillate recovery unit 4 distillation column 18 may generally operate at a pressure between about 5 mmHg and about 600 mmHg absolute, where the pressure varies within the distillation column 18. The temperature profile within the column 18 may depend on the pressure profile and the composition of the vapor and/or liquid along the length of the column. In some embodiments, the temperature within the column 18 may be between about 100° F. and about 600° F. In an embodiment, the overhead temperature in the distillation column 18 can be controlled to be about the same temperature or a lower temperature than the temperature at the top of distillation column 56 in the vacuum crude unit 6.

In some embodiments, a pump may not be present between the vacuum crude unit 6 and the vacuum distillate recovery unit 4 in line 12 or line 16. In order to provide the LVGO fraction to the vacuum distillate recovery unit 4, the pressure within the vacuum distillate recovery unit 4 at the line 16 inlet location may be lower than the pressure of the LVGO in line 12 from the vacuum crude unit 6. While the outlet pressure of the LVGO stream from the vacuum crude column 56 may in some instances be lower than the pressure at the line 16 inlet location, the outlet location of line 12 from the vacuum crude column 56 may be above the inlet location of line 16 into the distillation column 18. The height difference may contribute to a static fluid head pressure that accounts for the differences in pressure to drive the LVGO stream to the inlet location of line 16.

In an embodiment, the feed to the vacuum distillate recovery unit 4 includes the AGO fraction in line 10 from the atmospheric crude distillation column 101, the LVGO fraction in line 12 from the vacuum crude distillation column 56, and optionally, one or more additional streams in line 14. In an embodiment, the AGO fraction in line 10 can be mixed with the LVGO fraction in line 12 and potentially with other gas oil streams in line 14 to form a combined inlet stream in line 16. A surge/flash drum may be present in line 16 if the flow stability of the feeds to line 16 is not sufficiently stable. The surge/flash drum may also be used to control the conditions (e.g., the temperature, pressure, flowrate, etc.) of the inlet stream fed into the distillation column 18. For example, a control valve can be included in line 16 with or without a surge/flash drum to control the inlet flow rate and pressure into the column 18. In some embodiments, a feed preheater can be used to preheat the LVGO stream in line 12, the AGO stream in line 10, the optional stream in line 14, and/or the combined inlet stream in line 16. In this configuration, a feed pre-heater and/or heat exchange with another stream (e.g., heat exchange with the MGO stream in line 38) may be used to increase the enthalpy of the feed to the distillation column 18.

The combined inlet stream in line 16 can be separated within the distillation column 18 into a plurality of outlet streams. In an embodiment, the distillation column 18 in the vacuum distillate recovery unit 4 may separate the inlet stream into an overhead vapor stream in line 20, a product stream comprising a diesel fraction in line 32, and a product stream comprising a MGO fraction in stream 38. In an embodiment, fewer product streams may be present, and in some embodiments, additional product streams can be produced from the vacuum distillate recovery unit 4. The stream comprising the MGO fraction in line 38 may leave the system 48 for further processing such as being sent to an FCC unit and/or a hydrocracking unit.

In an embodiment, a pump-around system may be present and the diesel fraction in line 32 may be drawn from this system. In this system, outlet line 26 may draw fluid from the column 18 and split the stream into a plurality of lines including line 28, which can be reintroduced to the diesel/gas oil fractionating bed as a reflux stream, and line 30. Line 30 can be further split into a plurality of lines including line 32 comprising the diesel product fraction, and line 34. Line 34 can be cooled by a heat exchanger 35 to form the cooled stream in line 36 before being reintroduced into the column 18. In some embodiments, line 32 may be separated from line 36 after the heat exchanger 35 when cooling of the product stream is desired. The heat exchanger 35 can include any device suitable for removing heat from the stream in line 34. In an embodiment, the heat exchanger 35 can comprise a fin fan cooled exchanger, a cooling water exchanger, or a combination of both. The total heat removal duty of the heat exchanger 35 can be determined by the duty required to condense the diesel product stream in line 32, the amount of reflux in line 28, and the quantity of vapors flowing overhead into line 20. The reflux rate in line 28 can be controlled to produce the distillation specifications for the diesel product stream in line 32. In some embodiments, the reflux ratio as liquid reflux to vapor (LN) ratio at the top of the fractionating zone, below the diesel draw, may be between about 0.2 and about 0.8 on a volume basis.

In operation, a method of operating the system 48 may be similar to the operation of the system 8 described with respect to FIG. 4, and the full operation of the atmospheric crude unit 2 and the vacuum crude unit 6 are not repeated in the interest of clarity. To begin, the crude feed can be fed to the atmospheric crude unit 2 through line 100. The crude unit feed in line 100 can be desalted and heated by a fired heater and/or preheat train exchangers before entering the atmospheric crude unit 2 distillation column 101 to separate the crude feed into a light ends/naphtha stream in line 102, a stream comprising a kerosene fraction in line 103, a stream comprising a diesel fraction in line 104, a stream comprising an AGO fraction in line 10, and a stream comprising an atmospheric tower bottoms product fraction in line 50. Additional feed streams and/or product streams may be fed to the distillation column 101, and/or one or more of the product streams may not be present depending on the design of the atmospheric crude unit 2. The stream comprising the AGO fraction in line 10 can be stripped in a side stripper column.

The atmospheric tower bottoms product fraction (e.g., a residue fraction) in line 50 can pass to the vacuum crude unit 6 for further recovery of one or more gas oil fractions. As noted above, all or a portion of the ATB stream as well as potential ATB streams from other atmospheric crude units can be stored and sent from the storage to the vacuum crude unit 6 at a later time. A furnace 52 may be used with the atmospheric tower bottoms product fraction in line 50 to pre-heat the feed to the vacuum crude unit 6 in line 54. The vacuum system 64 may be in fluid communication with the upper portion of the vacuum crude unit 6 through line 62. In an embodiment, the vacuum crude unit 6 may separate the various components at a less than atmospheric pressure. Within the vacuum crude unit 6, the atmospheric tower bottoms product fraction (e.g., a residue fraction) in line 50 can be separated into a plurality of product streams, which can comprise a stream comprising an off-gas product in line 62, a stream comprising a LVGO fraction in line 12, a stream comprising a HVGO fraction in line 60, and a stream comprising a vacuum tower bottoms (VTB) product in line 58. As noted above, one or more of the streams illustrated in FIG. 5 may not be present and/or one or more additional streams such as a MVGO stream or a slop wax product stream may pass out of the vacuum crude unit 6. The off-gas product stream may pass to the vacuum system 64 through line 62. The stream comprising the LVGO fraction in line 12 may pass to the entrance of the vacuum distillate recovery unit 4 as described above.

The stream comprising the AGO fraction in line 10 from the atmospheric crude unit 2, the stream comprising the LVGO fraction in line 12, and optionally, an additional component stream in line 14 may be introduced into the vacuum distillate recovery unit 4 in one or more lines (e.g., in line 16, or as one or more separate lines into the column 18). The AGO fraction in line 10 may be at a higher temperature than the LVGO fraction in line 12. The combined inlet stream in line 16 may have an enthalpy that is sufficient to avoid the need for a heater in line 16, or between the atmospheric crude unit distillation column 101 and the vacuum distillate recovery unit distillation column 18, or between column 56 and column 18. As noted above, feed preheat may be used in some configurations and can be provided by a feed pre-heater and/or heat exchange with another stream or streams.

The vacuum distillate recovery unit 4 may be in fluid communication with the vacuum system 64 as described above so that the unit 4 may operate at a less than atmospheric pressure. A reboiler system may or may not be present with the distillation column 18 depending on the feed enthalpy, the column 18 operating pressure, and the reflux ratio necessary to obtain the selected recovery of diesel. In some embodiments, additional boil-up can be provided by a reboiler, side reboiler, or the like. The stream fed to the distillation column 18 may be separated to produce one or more product streams, which may comprise an overhead vapor stream in line 20, a stream comprising a diesel product fraction in line 32, and a stream comprising a Medium Gas Oil (MGO) fraction in line 38. In an embodiment, fewer product streams may be present, and in some embodiments, additional product streams can be produced from the vacuum distillate recovery unit 4.

The overhead line 20 from the distillation column 18 can be in fluid communication with the vacuum system 64 through line 22, which is in direct fluid communication with the vacuum system 64, and/or through line 24, which is in indirect fluid communication with the vacuum system 64 through the vacuum crude unit 6 distillation column 56. In some embodiments, only one of the lines 22, 24 is present, while in others both lines may be present. In an embodiment, the distillation column 18 may be in fluid communication with the vacuum system through line 24. This may allow the overhead stream in line 20 to pass through the vacuum crude unit 6 distillation column 56. The pressure of the distillation column 18 can be controlled through the use of a control valve between the vacuum system 64 and the distillation column 18. For example, a control valve can be located in line 20 and used to control the pressure within the top of the distillation column 18. The internal structures within the distillation column 18 may then determine the pressure profile along the length of the column.

Line 26 can be withdrawn from the distillation column 18. Line 26 can be separated into line 28, which can be refluxed to the distillation column 18, and line 30. Various equipment such as one or more control valves and the like can be used to control the relative flowrate of the streams into each of lines 28 and 30. Line 30 can be separated into a plurality of lines including the diesel product stream in line 32 and a pump-around stream in line 34. Various equipment such as one or more control valves and the like can be used to control the relative flowrate of the streams into each of lines 32 and 34. Line 34 can be cooled in the heat exchanger 35 and return to the distillation column 18 from the heat exchanger 35 through line 36. In some embodiments, line 32 may be separated from line 36 after the heat exchanger 35 when cooling of the product stream is desired. Line 32 can then exit the system 48 to provide a diesel product stream. As described in more detail herein, the diesel fraction in line 32 may fall within the diesel boiling point range, and may have a different composition than the diesel product stream in line 104. In some embodiments, the diesel fraction in stream 32 comprises diesel range components but can also comprise other lighter distillate components such as jet fuel and kerosene fractions. A refinery configuration can include a distillate hydrotreater with a distillation column downstream of the vacuum distillate recovery unit 4 that can receive the diesel fraction in stream 32 and recover hydrotreated diesel as well as other products (e.g., naphtha, jet fuel, etc.).

FIG. 6 illustrates another embodiment of a system 68 for recovering diesel from a crude stream. The system 68 may be similar to the system 8 described with respect to FIG. 4 and the system 48 described with respect to FIG. 5. Like components will not be described again in the interest of clarity. The main difference between the system 68 and the previously described systems is the presence of a Light Gas Oil (LGO) recovery stream in the vacuum distillate recovery unit 74. The LGO recovery stream may exit the distillation column 18 through line 46. In an embodiment, the LGO product stream in line 46 may be taken from the distillation column 18 at a location below the diesel/gas oil fractionating bed and above the distillation column 18 feed location (e.g., above the inlet line 16 location). The recovery of a separate LGO stream may allow the distillation column 18 to produce an LGO stream and a medium boiling range gas oil stream, which may improve the ability to selectively provide the product streams to various downstream processing units.

Depending on the design of the system, the use of the distillation column 18 to perform the additional separation of the LGO stream may require a greater feed enthalpy than is present in the feed stream in line 16. In this embodiment, a reboiler 42 may be associated with the distillation column 18 to provide the additional heat input. The reboiler may draw a stream of liquid phase hydrocarbons from the stripping section zone and vaporize at least a portion of the liquid to produce a heated stream in line 44. The heated stream can then be returned to the distillation column 18. In some embodiments, a side reboiler may be used to draw a stream from the distillation column 18 at any point along its length to provide additional boil-up. The reboiler 42 and/or a side reboiler can comprise any suitable device for heating and at least partially vaporizing the liquid stream such as a heat exchanger, a heater (e.g., a furnace, etc.) or the like. In some embodiments, a base heater may be used within the distillation column to vaporize a portion of the liquids within the column prior to allowing the product stream comprising a MGO fraction to pass out of the distillation column 18 through line 38.

The operation of the system 68 may be the same or similar to the operation of the system 8 described with respect to FIG. 4 and the system 48 described with respect to FIG. 5. The operation of similar components is not repeated in the interest of clarity. As shown in FIG. 6, the stream comprising the AGO fraction in line 10 from the atmospheric crude unit 2, the stream comprising the LVGO fraction in line 12, and optionally, an additional component stream 14 may be introduced into the vacuum distillate recovery unit 74 in one or more lines (e.g., in line 16). The stream fed to the distillation column 18 may be separated to produce one or more product streams, which may comprise an overhead vapor stream in line 20, a stream comprising a diesel product fraction in line 32, a stream comprising a LGO fraction in line 46, and a stream comprising MGO fraction in line 38.

Within the distillation column 18, a liquid stream may be withdrawn from the lower portion of the column (e.g., from the stripping section) and passed through line 40 to a reboiler 42. The liquid can be at least partially vaporized to create heated stream in line 44, which can be returned to the distillation column 18 to create a rising vapor phase. If a side reboiler is present, the vapor from the side reboiler can be introduced into the distillation column 18 to form a portion of the rising vapor phase. A LGO stream can be withdrawn from the column through line 46, which may be located above the feed. The resulting LGO stream in line 46 can leave the system 68 for further processing such as being sent to an FCC unit, a hydrocracking unit, and/or a hydrotreater. The remainder of the system 68 may operate as described above with reference to the system 48 described with respect to FIG. 5.

FIG. 7 illustrates still another embodiment of a system 78 for recovering diesel from a crude stream. The system 78 may be similar to the system 8 described with respect to FIG. 4, the system 48 described with respect to FIG. 5, and/or the system 68 described with respect to FIG. 6. Like components will not be described again in the interest of clarity. The main difference between the system 78 and the previously described systems is the presence of a separate vacuum system 49 for use with the vacuum distillate recovery unit 4. In this embodiment, the overhead vapor product stream in line 20 can flow into the separate vacuum system 49. The vacuum system 49 may comprise any of the components described with respect to the vacuum system 64. The vacuum system 49 may be the same or similar to the vacuum system 64, or the vacuum system 49 may be different than the vacuum system 64. For example, the capacity of the vacuum systems may be different depending on the expected throughput of each unit. In an embodiment, the use of the separate vacuum system 49 may be used with any of the previous described embodiments including the embodiment of FIG. 6 with the LGO outlet line and the reboiler associated with the distillation column 18.

The use of the separate vacuum system 49 may be advantageous in some situations. For example, the use of a separate vacuum system could enable the vacuum distillate recovery unit 4 to process other gas oil streams having kerosene and lighter boiling range materials. For example, the optional inlet stream in line 14 may comprise lighter boiling components. When lighter components are present, the use of a single vacuum system 64 associated with the vacuum crude unit 6 may have a negative effect on the operating pressure achievable in both the vacuum crude unit 6 distillation column 56 and the vacuum distillate recovery unit 4 distillation column 18. Specifically, the light boiling range material would pass to the vacuum system 64 and limit the ability of the vacuum system to reduce the pressure in the columns. This would increase the operating pressure within the distillation columns 56, 18 and consequently decrease the product yields of the vacuum crude unit 6 and the vacuum distillate recovery unit 4. Thus, using the separate vacuum system 49 may allow the vacuum system 49 to handle a lighter hydrocarbon feed composition.

The operation of the system 78 may be the same or similar to the operation of the system 8 described with respect to FIG. 4, the operation of the system 48 described with respect to FIG. 5, and/or the operation of the system 68 described with respect to FIG. 6. However, the use of a separate vacuum system 49 may allow the pressure in each column 18, 56 to be independently adjusted. In this embodiment, the pressure profile may vary between each column 18, 56. If the pressure within the distillation column 18 in the vacuum distillate recovery unit 4 is higher than the pressure within the distillation column 56 in the vacuum crude unit 6, then a pump may be used to increase the pressure of the LVGO stream in line 12.

The systems and methods described herein result in the production of a plurality of diesel streams including the diesel product stream in line 104 from the atmospheric crude unit 2 and the diesel product stream in line 32 from the vacuum distillate recovery unit 4. The two diesel product streams may have different compositions due to the order in which the two streams are separated. While most of the components may overlap to some degree, the proportion of the components may be different. It is expected that the diesel product stream in line 104 will have a higher proportion of light boiling range hydrocarbons than the diesel product stream in line 32, and the diesel product stream in line 32 will have a higher proportion of heavier boiling range hydrocarbons than the diesel product stream in line 104.

The production of multiple diesel product streams having different compositions may allow a refiner to use the streams separately, or selectively blend the streams to meet various diesel specifications. In an embodiment, the diesel product streams can be blended to meet various diesel product specifications such as home heating oil, No. 1 Diesel, No. 2 Diesel, and the like.

In some embodiments, the diesel product streams, or some portion thereof, can be used in a downstream processing unit. For example, the production of different diesel streams may allow each stream to be treated in separate hydrotreater to meet process unit capacity limitations. The production of different diesel streams with different compositions may allow the feed to the downstream production units to be selected to produce a desired treated product. This may beneficially improve the operation of the overall process while producing a desired diesel product or products.

At least one embodiment is disclosed and variations, combinations, and/or modifications of the embodiment(s) and/or features of the embodiment(s) made by a person having ordinary skill in the art are within the scope of the disclosure. Alternative embodiments that result from combining, integrating, and/or omitting features of the embodiment(s) are also within the scope of the disclosure. Where numerical ranges or limitations are expressly stated, such express ranges or limitations should be understood to include iterative ranges or limitations of like magnitude falling within the expressly stated ranges or limitations (e.g., from about 1 to about 10 includes, 2, 3, 4, etc.; greater than 0.10 includes 0.11, 0.12, 0.13, etc.). For example, whenever a numerical range with a lower limit, R₁, and an upper limit, R_(u), is disclosed, any number falling within the range is specifically disclosed. In particular, the following numbers within the range are specifically disclosed: R=R₁+k*(R_(u)−R₁), wherein k is a variable ranging from 1 percent to 100 percent with a 1 percent increment, i.e., k is 1 percent, 2 percent, 3 percent, 4 percent, 5 percent, . . . 50 percent, 51 percent, 52 percent, . . . , 95 percent, 96 percent, 97 percent, 98 percent, 99 percent, or 100 percent. Moreover, any numerical range defined by two R numbers as defined in the above is also specifically disclosed. Use of the term “optionally” with respect to any element of a claim means that the element is required, or alternatively, the element is not required, both alternatives being within the scope of the claim. Use of broader terms such as comprises, includes, and having should be understood to provide support for narrower terms such as consisting of, consisting essentially of, and comprised substantially of. Accordingly, the scope of protection is not limited by the description set out above but is defined by the claims that follow, that scope including all equivalents of the subject matter of the claims. Each and every claim is incorporated as further disclosure into the specification and the claims are embodiment(s) of the present invention. 

What is claimed is:
 1. A system for recovering diesel products from a feed stream, the system comprising: an atmospheric crude unit, wherein the atmospheric crude unit comprises a crude feed inlet line, a diesel product outlet line, an atmospheric gas oil product outlet line, and a residual product outlet line; a vacuum crude unit, wherein the vacuum crude unit comprises a residual product inlet line, a light vacuum gas oil product outlet line, and an overhead vapor outlet line, wherein the residual product inlet line is in fluid communication with the residual product outlet line; and a vacuum distillate recovery unit, wherein the vacuum distillate recovery unit comprises a gas oil inlet line, an overhead product line, and a second diesel product outlet line, wherein the gas oil inlet line is in fluid communication with the atmospheric gas oil product outlet line from the atmospheric crude unit and the light vacuum gas oil product outlet line from the vacuum crude unit.
 2. The system of claim 1, further comprising: a vacuum system, wherein the vacuum system is in fluid communication with the overhead vapor outlet line from the vacuum crude unit and the overhead product line from the vacuum distillate recovery unit.
 3. The system of claim 1, further comprising: a vacuum system, wherein the vacuum system is in fluid communication with the overhead vapor outlet line from the vacuum crude unit, and wherein the overhead product line from the vacuum distillate recovery unit is in fluid communication with the vacuum crude unit.
 4. The system of claim 1, further comprising: a first vacuum system in fluid communication with the overhead vapor outlet line from the vacuum crude unit, and a second vacuum system in fluid communication with the overhead product line from the vacuum distillate recovery unit.
 5. The system of claim 1, wherein the vacuum distillate recovery unit comprises a distillation column comprising the gas oil inlet line, the overhead product line, and the second diesel product outlet line, wherein the distillation column comprises a side draw line in fluid communication with the second diesel product outlet line and a cooling circuit, wherein the cooling circuit comprises a heat exchanger configured to cool at least a portion of a fluid stream drawn from the distillation column through the side draw line and return the cooled portion of the fluid stream to the distillation column.
 6. The system of claim 1, wherein the vacuum distillate recovery unit comprises a distillation column comprising the gas oil inlet line, the overhead product line, and the second diesel product outlet line, wherein the distillation column further comprises a reboiler configured to vaporize a portion of a liquid in the lower portion of the distillation column and return a vapor to the distillation column.
 7. The system of claim 6, wherein the distillation column further comprises a light gas oil outlet line.
 8. The system of claim 7, wherein the light gas oil outlet line is located above the gas oil inlet line and below the second diesel product outlet line.
 9. A method of recovering diesel from a crude oil feed stream, the method comprising: separating a crude oil feed stream into a plurality of streams in an atmospheric crude unit, wherein the plurality of streams comprise a first diesel product stream, an atmospheric gas oil stream, and a residual product stream; receiving the atmospheric gas oil stream and a light vacuum gas oil stream at a distillation column; and separating the atmospheric gas oil stream and the light vacuum gas oil stream into a plurality of product streams in the distillation column, wherein the plurality of product streams comprise an overhead vapor stream, a second diesel product stream, and a medium gas oil stream.
 10. The method of claim 9, further comprising: separating the residual product stream in a vacuum crude unit into a plurality of product streams, wherein the plurality of product streams comprise the light vacuum gas oil stream.
 11. The method of claim 10, wherein the vacuum crude unit is in fluid communication with a vacuum system while separating the residual product stream.
 12. The method of claim 11, wherein the distillation column is in fluid communication with the vacuum system while separating the atmospheric gas oil stream and the light vacuum gas oil stream.
 13. The method of claim 11, wherein the distillation column is in fluid communication with a second vacuum system while separating the atmospheric gas oil stream and the light vacuum gas oil stream, wherein the vacuum system and the second vacuum system are separate vacuum systems.
 14. The method of claim 9, further comprising combining the atmospheric gas oil stream and the light vacuum gas oil stream before separating the atmospheric gas oil stream and the light vacuum gas oil stream into the plurality of product streams.
 15. The method of claim 9, wherein separating the atmospheric gas oil stream and the light vacuum gas oil stream comprises: introducing the atmospheric gas oil stream and the light vacuum gas oil stream into the distillation column; removing a fluid stream from the distillation column during the separation; passing a first portion of the fluid stream back to the distillation column; passing a second portion of the fluid stream to a heat exchanger; cooling the second portion of the fluid stream in the heat exchanger to create a cooled fluid; passing the cooled fluid back to the distillation column; and removing a third portion of the fluid stream as the second diesel product stream.
 16. The method of claim 15, wherein separating the atmospheric gas oil stream and the light vacuum gas oil stream further comprises: removing a second fluid stream from the distillation column during the separation, wherein the second fluid stream is removed from below the fluid stream and above a location at which the atmospheric gas oil stream and the light vacuum gas oil stream are introduced into the distillation column, wherein the second fluid stream comprises a light gas oil product stream.
 17. The method of claim 16, wherein separating the atmospheric gas oil stream and the light vacuum gas oil stream further comprises: reboiling a portion of a liquid stream in a lower portion of the distillation column during the separating.
 18. A method of recovering diesel, the method comprising; separating a crude oil feed stream into a plurality of product streams in an atmospheric crude unit, wherein the plurality of product streams comprises a first diesel product stream, an atmospheric gas oil stream, and a residual product stream; separating the residual product stream into a plurality of second product streams in a vacuum crude unit, wherein the plurality of second product streams comprises a light vacuum gas oil and an overhead stream; receiving the atmospheric gas oil stream and the light vacuum gas oil stream at a distillation column; and separating the atmospheric gas oil stream and the light vacuum gas oil stream into a plurality of third product streams in the distillation column, wherein the plurality of third product streams comprises a second diesel product stream.
 19. The method of claim 18, wherein the plurality of third product streams comprises a second overhead stream, and wherein the overhead stream from the vacuum crude unit and the second overhead stream from the distillation column are in fluid communication with a vacuum system.
 20. The method of claim 18, wherein the plurality of third product streams comprises a second overhead stream, and wherein the second overhead stream is in fluid communication with the vacuum crude unit, and wherein the overhead stream from the vacuum crude unit is in fluid communication with a vacuum system. 